1. Field of the Invention
The invention relates generally to cutting structures used to drill wells in the earth. More specifically, the invention relates to PDC cutting structures for expandable downhole reaming tools.
2. Background Art
Polycrystalline diamond compact (PDC) cutters have been used in industrial applications including rock drilling and metal machining for many years. In these applications, a compact of polycrystalline diamond (or other superhard material such as cubic boron nitride) is bonded to a substrate material, which is typically a sintered metal-carbide, to form a cutting structure. A compact is a polycrystalline mass of diamonds (typically synthetic) that are bonded together to form an integral, tough, high-strength mass.
An example of a use of PDC cutters is in a rock bit for earth formation drilling as disclosed in U.S. Pat. No. 5,186,268. FIG. 1 from that patent shows a cross section of a rotary drill bit having a bit body 10. A lower face of the bit body 10 is formed with a plurality of blades (blade 22 is shown in FIG. 1) that extend generally outwardly away from a rotational axis 15 of the drill bit. A plurality of PDC cutters 26 are disposed side by side along the length of each blade. The number of PDC cutters 26 carried by each blade may vary. The PDC cutters 26 are brazed to a stud-like carrier, which may also be formed from tungsten carbide, and is received and secured within a socket in the respective blade.
When drilling a typical well, a PDC bit is run on the end of a bottom hole assembly (BHA) and the PDC bit drills a wellbore with a selected diameter. However, there are limitations on the diameter of a wellbore that may be drilled with a conventional drill bit. For example, a wellbore may comprise steel casing that has already been set in the well. Therefore, the diameter of the drill bit attached to the BHA is limited by a “pass-though” diameter (e.g., a minimum required diameter through which the drill bit may pass, such as the internal diameter of the steel casing). Accordingly, several attempts have been made to design drill bits and downhole tools that can effectively “drill out” or “underream” a wellbore below, for example, casing that has been set in the wellbore.
Prior art underreamers are typically separate tools that are run into the wellbore in a separate trip. These underreamers require that the BHA (e.g., the BHA with the drill bit) be brought to the surface and exchanged with an underreaming BHA. This is a costly operation because of the time required to make an additional trip in and out of the well to exchange the standard BHA for the underreaming BHA, especially in offshore operations. Accordingly, efforts have been made to design downhole tools that could be run into the wellbore on a standard BHA and effectively “underream while drilling.” Underreaming while drilling eliminates extra trips in and out of the wellbore and the associated rig downtime.
An example of such an attempt to develop an underreaming capable BHA is the development of the bi-center drill bit. A typical bi-center bit comprises a pilot section having an axis of rotation substantially coaxial with a rotational axis of the BHA. The bi-center bit also includes a reaming section, typically characterized by a blade arrangement that has a center of rotation that is offset from the rotational axis of the BHA. Rotation of the reaming section about the bit axis enables the bi-center bit to drill a larger diameter hole than would ordinarily be drilled by the gage diameter of the pilot bit section alone. Moreover, a particular advantage of the bi-center drill bit is that it has a pass-through diameter that is less than a drill diameter of the reaming section so that the bi-center bit can be passed through casing with a diameter smaller than a desired reamed diameter and then rotated so as to underream the formation beneath the casing. An example of a bi-center bit is shown in U.S. Pat. No. 6,039,131 issued to Beaton.
Another device that has been developed is the near-bit reamer. Near-bit reamers may be run into a wellbore with typical steerable BHAs, and the near-bit reamers are generally activated downhole by, for example, hydraulic pressure. When activated, a pressure differential is created between an internal diameter of the reamer and a wellbore annulus. The higher pressure inside the reamer activates pistons that radially displace a reamer cutting structure. The reamer cutting structure is typically symmetrical about a wellbore axis, including, for example, expandable pads that comprise cutting elements. The cutting elements are moved into contact with formations already drilled by the drill bit, and the near-bit reamer expands the diameter of the wellbore by a preselected amount defined by a drill diameter of the expanded reamer outing structure.
Prior art near-bit reamers generally include cutting structures that are fairly rudimentary in design. While PDC cutters are commonly used with near-bit reamers, the PDC cutters are generally arranged in a relatively simplistic fashion.
Therefore, it would be advantageous to produce near-bit reamer cutting structures that incorporate, for example, advanced cutting structures used on PDC drill bits.